Search Results (25)

Ultra-tight gas reservoirs present severe flow constraints due to complex interactions between rock–fluid properties and hydraulic fracturing. This study investigates the impact of unconventional capillary pressure correlations and permeability jail effects on post-fracture cleanup in multiple-fractured horizontal wells (MFHWs) using high-resolution numerical simulations. A novel modelling approach is applied to represent both weak and strong permeability jail phenomena in heterogeneous rock systems. A comprehensive suite of parametric simulations evaluates gas production loss (GPL) and produced fracture fluid (PFF) across varying fracture fluid volumes, shut-in times, drawdown pressures, and matrix permeabilities. The analysis leverages statistically designed experiments and response surface models to isolate the influence of rock heterogeneity and saturation-dependent flow restrictions on cleanup efficiency. The results reveal that strong jail zones drastically hinder fracture fluid recovery, while weak jail configurations interact with heterogeneity to produce non-linear cleanup trends. Notably, reducing the pore size distribution index in Pc models improves predictive accuracy for ultra-tight conditions. These findings underscore the need to integrate unconventional Kr and Pc behaviour in hydraulic fracturing design to optimise flowback and long-term gas recovery. This work provides critical insights for improving reservoir performance and supports ambitions in energy resilience and net-zero transition strategies. Full article

The rapid expansion of shale gas development has revolutionized global energy markets, yet it has also introduced substantial environmental challenges, particularly concerning groundwater resources. This comprehensive review systematically examines the multifaceted impacts of shale gas extraction on groundwater, with a focus on contamination mechanisms, pollutant sources, and mitigation strategies. The study identifies key operational stages—exploration, drilling, hydraulic fracturing, and flowback—as potential sources of groundwater contamination. Inorganic pollutants, including heavy metals and radionuclides, as well as organic compounds such as hydrocarbons and chemical additives, are identified as primary contaminants. The review critically evaluates current wastewater treatment technologies, including reinjection, internal reuse, and advanced desalination methods, highlighting their efficacy and limitations. Additionally, the study proposes a refined environmental management framework that integrates wellbore integrity optimization, enhanced shale gas wastewater treatment, and stringent monitoring protocols. The adoption of clean fracturing technologies and renewable energy applications is recommended to minimize environmental footprints. By establishing comprehensive baseline data and robust pollution monitoring systems, this research provides a scientific foundation for sustainable shale gas development, ensuring the protection of groundwater resources. This review emphasizes the imperative of balancing energy security with environmental sustainability, offering actionable insights for policymakers, industry stakeholders, and environmental scientists. Full article

With the continued advancement of shale gas development, the issue of frac hit has become increasingly prominent and has emerged as a key factor influencing the production of shale gas wells. Quantitative evaluation of the impact of frac hit on shale gas wells and proposing different methods to prevent frac hit are of great significance for the efficient development of shale gas. This research puts forward a machine learning-based workflow that incorporates geological and engineering factors to evaluate the impacts of frac hit. The “Frac Hit Pressure Integral Index (FPI)” quantifies the dynamic pressure responses by means of the ratios of initial pressure to shut-in pressure. Pearson analysis is employed to reduce the dimensionality of parameters, and Random Forest and K-means++ algorithms are utilized to classify the risks of frac hit. Among numerous influencing factors, it has been found that the brittleness index and well spacing possess the highest weights among the geological and engineering influencing factors, reaching 20.4 and 16.1, respectively. The L well area of southern Sichuan shale gas lies in the Fuji syncline of the Huaying Mountain tectonic system’s low-fold Fujian zone. When applied to the L well area in the Sichuan Basin, the results pinpoint the brittleness index, fluid intensity, and well spacing as crucial factors. It is recommended that, for reservoirs with high fracturability, reducing fluid intensity and increasing well spacing can minimize inter-well interference. This workflow classifies risks into low (FPI ≤ 265.43), medium (265.43 < FPI < 658.56), and high levels (FPI ≥ 658.56) and recalibrates natural fracture zones based on pressure and flowback data, thereby enhancing the alignment between geological and engineering aspects by 10%. This framework optimizes fracturing designs and mitigates inter-well interference, providing support for the efficient development of shale gas. Full article

EZFLOW weak gel drilling fluid, a drilling fluid system with distinctive internal architecture, has been extensively implemented in horizontal well drilling operations at the Western South China Sea oilfields. Its unique internal structure causes specific functional mechanisms. The rheological mechanism was investigated through microstructural characterization, revealing that the microstructure comprises a reversible network structure with sol particles either encapsulated within the network or embedded at nodal points. This distinctive spatial network configuration endows the system with exceptional rheological properties. The plugging mechanism was elucidated via pre- and post-PPA test characterization of sand disc surface morphology. Experimental results demonstrate that the rheology modifier EZVIS forms deformable aggregates and films through intermolecular or intramolecular association in aqueous solutions, effectively plugging micro-nano pores/throats and microfractures to inhibit drilling fluid filtrate invasion. Concurrently, the rigid plugging material EZCARB establishes physical barriers at micro-nano pores/throats through bridging mechanisms. Notably, the dense filter cake formed by EZFLOW weak gel drilling fluid exhibits poor flowback characteristics, potentially inducing reservoir damage. Based on mechanistic analyses of rheological behavior, plugging performance, and filter cake composition, a filter cake removal fluid formulation was developed through: (1) creation of retarded acid HWCP to degrade polymer EZVIS and dissolve temporary plugging agent EZCARB; (2) development of corrosion inhibitor HWCI to mitigate corrosion rates. Laboratory evaluations demonstrated effective filter cake elimination and reservoir protection capabilities. Post-treatment analysis of EZFLOW-contaminated reservoir cores showed complete filter cake removal at core end faces with permeability recovery values exceeding 95%, indicating superior filter cake dissolution capacity and reservoir protection performance that significantly reduces formation damage. Full article

The ecological impact linked to hydraulic fracturing, namely with the usage of water and the energy-intensive disposal of flowback fluids, has led to a thorough evaluation of alternative treatment approaches that are more environmentally friendly. The objective of this work was to create coralline-like anatase TiO₂/α-Ni(OH)₂ particles using a hydrothermal approach. The purpose was to improve the efficiency of photocatalysis by increasing the number of oxygen vacancies. An ozone-assisted photocatalytic reaction was used to increase the composite photocatalyst’s degrading efficiency for fracturing flowback fluid. The fracturing flowback fluid’s chemical oxygen demand (COD) degradation efficiency was greatly increased following the introduction of the synergistic treatment system consisting of sedimentation, membrane separation, and ozone photocatalysis. This improvement led to a reduction of 98.42% during a processing time of 90 min, using a Ti/Ni mass ratio of 1:1. This collaborative method partially replaced traditional methods of evaporation concentration and electrochemical degradation, resulting in a 24.18% enhancement compared to individual material catalyst systems. These findings provide crucial insights for improving and optimizing external treatment techniques in shale gas fracturing operations. Full article

Acid fracturing has become a crucial technology for developing carbonate reservoirs, playing a particularly significant role in enhancing oil and gas recovery. However, the retention and flowback behaviors of residual acid in fractured-vuggy carbonate reservoirs after acid fracturing remain poorly understood, and this uncertainty significantly hinders the efficient development of such reservoirs. In this study, the micro-computed tomography images of carbonate rocks were used to extract actual fracture–vug structures. A microscopic flow model for fractured-vuggy carbonate reservoirs was then designed and fabricated using wet etching techniques. Microfluidic experiments were performed to investigate the invasion and flowback behavior of residual acid within these reservoirs. This study introduces a novel approach by integrating actual fracture-vuggy structures from micro-CT images into a microfluidic model, providing a more realistic representation of fractured-vuggy carbonate reservoirs compared to previous studies that relied on simplified or idealized geometries. Additionally, the invasion coefficient (the ratio of acid invaded area to total pore area) and flowback rate (the proportion of residual acid expelled during flowback) were introduced to quantitatively assess the efficiency of acid invasion and flowback under varying flow rates, viscosities, and the presence or absence of surfactants. The results demonstrate that the invasion coefficient of residual acid increases with the injection rate, while the flowback rate decreases as the injection rate is reduced. A higher viscosity of the oil phase hinders acid invasion and results in slower flowback due to increased flow resistance in the micro model. However, the final flowback rate is higher with a higher viscosity oil phase compared to a lower viscosity phase. The addition of surfactants enhances the efficiency of acid invasion and flowback, increasing the invasion coefficient by up to 5% and the flowback rate by up to 3%. Full article

In order to solve the problems of long dissolution and preparation time, cumbersome preparation, and easy moisture absorption and deterioration during storage or transportation, acrylamide (AM), acrylic acid (AA), sodium p-styrene sulfonate (SSS), and cetyl dimethylallyl ammonium chloride (DMAAC-16) were selected as raw materials, and the emulsion thickener P(AM/AA/SSS), which can be instantly dissolved in water and rapidly thickened, was prepared by the reversed-phase emulsion polymerization method. DMAAC-16, the influence of emulsifier dosage, oil–water ratio, monomer molar ratio, monomer dosage, aqueous pH, initiator dosage, reaction temperature, reaction time, and other factors on the experiment was explored by a single-factor experiment, and the optimal process was determined as follows: the oil–water volume ratio was 0.4, the emulsifier dosage was 7% of the oil phase mass, the initiator dosage was 0.03% of the total mass of the reaction system, the reaction time was 4 h, the reaction temperature was 50 °C, the aqueous pH was 6.5, and the monomer dosage was 30% of the total mass of the reaction system (monomeric molar ratio n(AM):n(AA):n(SSS):n(DMAAC-16) = 79.2:20:0.5:0.3). X-ray diffraction analysis (XRD), infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), and scanning electron microscopy analysis were carried out on the polymerization products. At the same time, a series of performance test experiments such as thickening performance, temperature and shear resistance, salt resistance, sand suspension performance, core damage performance, and fracturing fluid flowback fluid reuse were carried out to evaluate the comprehensive effect and efficiency of the synthetic products, and the results show that the P(AM/AA/SSS/DMAAC-16) polymer had excellent solubility and excellent properties such as temperature and shear resistance. Full article

This work establishes an analytical model for determining the critical velocity for proppant flowback, and evaluates how proppant flowback affects fracture conductivity for tight reservoirs. The multiphase effects are considered for determining the critical velocity for proppant flowback before and after fracture closure, respectively. The model’s performance is demonstrated by comparing the results against previous models. A finite-element model is built to simulate the proppant flowback process for a hydraulic-fractured well completed in the Ordos Basin. The change in fracture conductivity caused by proppant flowback for several scenarios with varying saturation and net pressure in fractures is further quantitatively assessed. Our results highlight the importance of multiphase effects in determining the critical velocity for proppant flowback at relatively low water saturation in fractures. The critical velocity generally increases with increasing water saturation in fractures and net pressure in fractures. At a flowback velocity higher than the critical value, the loss in fracture conductivity becomes relatively more pronounced at a lower water saturation in fractures and a lower net pressure in fractures. The findings of this work are expected to provide insights into the mechanisms of proppant flowback and flowback drawdown management for field operations in tight reservoirs. Full article

The conventional liquid acid has several shortcomings in the acidizing process of fractured-vuggy carbonate reservoirs, including high filtration loss, fast reaction rate, high friction resistance, and difficult flowback. To address these issues, a new atomizing acid acidizing technology is proposed, combining the gas injection development practice from the fractured-vuggy carbonate reservoir in the Tahe oilfield. The laboratory experiments were conducted to optimize the type and concentration of atomized acid, iron ion stabilizer, corrosion inhibitor, and atomization stabilizer. The acid atomization rate was evaluated under different combinations of gas and liquid injection flows using a self-made atomized acid well migration simulator, and the best atomization scheme was selected. Furthermore, a kinetic experiment for the acid–rock reaction was carried out to evaluate the retarding performance of the atomized acid. The optimized formula for the atomizing acid system consists of 15~25% hydrochloric acid, 0.005% atomizing stabilizer (AEO-7), 1% iron ion stabilizer (EET), 1.5% corrosion inhibitor (EEH-160), and water. The optimal gas and acid injection scheme is gas injection at 2m3/min and acid injection at 10 mL/min, which maintains an atomization rate of over 80% after the acid mist migrates through the wellbore. Compared with gelling acid, the acid–rock reaction rate of atomized acid is 8.5, 9.1, and 10.6 times slower under acid concentrations of 15%, 20%, and 25% respectively. The retarding effect of atomized acid is superior, facilitating etching and initiating underdeveloped gas drive channels and thereby increasing the probability of gas communication with new reservoirs. The research findings presented in this paper establish a theoretical foundation for the practical implementation of the atomized acid acidizing process in the field. Full article

The presence of a reasonable flowback system after fracturing is a necessary condition for the high production of shale gas wells. At present, the optimization of the flowback system lacks a relevant theoretical basis. Due to this lack, this study established a new method for evaluating the conductivity of artificial fractures in shale, which can quantitatively characterize the backflow, embedment, and fragmentation of proppant during the flowback process. Then, the mechanism of the stress sensitivity of artificial fractures on fracture conductivity during the flowback stage of the shale gas well was revealed by performing the artificial fracture conductivity evaluation experiment. The results show that a large amount of proppant migrates, and the fracture conductivity decreases rapidly in the early stage of flowback, and then the decline gradually slows down. When the effective stress is low, the proppant is mainly plastically deformed, and the degree of fragmentation and embedment is low. When the effective stress exceeds 15.0 MPa, the fragmentation and embedment of the proppant will increase, and the fracture conductivity will be greatly reduced. The broken proppant ratio and embedded proppant ratio are the same under the two choke-management strategies. In the mode of increasing choke size step by step, the backflow proppant ratio is lower, and the broken proppant is mainly retained in fractures, so the damage ratio of fracture conductivity is lower. In the mode of decreasing choke size step by step, most of the proppant flows back from fractures, so the damage to fracture conductivity is greater. The research results have important theoretical guiding significance for optimizing the flowback system of shale gas wells. Full article

Temporary plugging diversion fracturing (TPDF) technology has been widely used in various oil fields for repeated reconstruction of high-water-cut old oil wells and horizontal well reservoir reconstruction. Previous studies have carried out in-depth study on the pressure-bearing law and placement morphology of different types of temporary plugging agents (TPAs) in fractures, but there are relatively few studies on TPA accumulation body permeability. To solve this problem, an experimental device for evaluating the TPA performance with adjustable fracture pores is proposed in this paper. Based on the test of fracturing fluid breaking time and residue content, the low damage of fracturing fluid to the reservoir is determined. The TPA degradation performance test determines whether the TPA causes damage to the hydraulic fracture after the temporary plugging fracturing. Finally, by testing the TPA pressure-bearing capacity and the temporary plugging aggregation body permeability, the plugging performance and the aggregation body permeability are determined. The results show the following: (1) Guar gum fracturing fluid shows good gel-breaking performance under the action of breaking agent, and the recommended concentration of breaking agent is 300 ppm. At 90~120 °C, the degradation rate of the three types of TPAs can reach more than 65%, and it can be effectively carried into the wellbore during the fracturing fluid flowback stage to achieve the effect of removing the TPA in the fracture. (2) The results of the pressure-bearing performance of the TPA show that the two kinds of TPAs can quickly achieve the plugging effect after plugging start: the effect of ZD-2 (poly lactic-co-glycolic acid (PLGA)) particle-and-powder combined TPA on forming an effective temporary plugging accumulation body in fractures is better than that of ZD-1 (PLGA) pure powder. There are large pores between the particles, and the fracturing fluid can still flow through the pores, so the ZD-3 (a mixture of lactide and PLGA) granular temporary plugging agent cannot form an effective plugging. (3) The law of length of the temporary plugging accumulation body shows that the ZD-2 combined TPA has stronger plugging ability for medium-aperture simulated fracture pores, while the ZD-1 powder TPA has stronger plugging ability for small aperture simulated fracture pores, and the ZD-3 granular TPA should be avoided alone as far as possible. This study further enriches and improves the understanding of the mechanism of temporary plugging diverting fracturing fluid. Full article

For tight reservoirs, horizontal wells and multi-stage fracturing can generate a complex fracture network that realizes economic and effective development. The volume and complexity of the fracture network are of great significance to accurately predicting the productivity of tight oil wells. In this work, a mathematical model of a multiphase flow is proposed to evaluate the stimulation effect based on the early flowback data. The model showing the early slope of the material balance time (MBT) and production balance pressure (RNP) can help estimate the effective stimulated volume of the horizontal well. The linear flow region can be determined from the slope of the log–log plot of the MBT versus RNP curve, which equals 1. The method is verified by commercial simulation software, and the calculated stimulated volume is consistent with the statistical results of simulation results. Results also show that the flow pattern of the fracture–matrix system can be judged by the slope of the flowback characteristic curve in the early stage of flowback, and then the complexity of the fracture network can also be obtained. The proposed method can provide an avenue to evaluate the fracturing work using the flowback data quickly. Full article

The Marcellus shale is an unconventional reservoir of significant economic potential with Total Organic Carbon (TOC) ranging from 1 to 20%. Hydraulic fracturing is used to extract the shale’s resources, which requires large amounts of water and can result in mineral-rich flowback waters containing hazardous contaminants. This study focuses on a geochemical analysis of the flowback waters and an evaluation of the potential environmental impacts on water and soil quality. Drilled core samples from different depths were treated with lab-prepared hydraulic fracturing fluids. Rock samples were analyzed using Energy Dispersive Spectroscopy (EDS), while effluents’ chemical compositions were obtained using Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES). A comparison of results from drilled core samples treated with additives for hydraulic fracturing to those treated with deionized (DI) water confirms that, as expected, the major elements present in the effluent were Ca, Ba, and Cl in concentrations greater than 100 µg/L. The most concerning elements in the effluent samples include As, Ca, Cd, Pb, Se, S, K, Na, B, Mo, and Mn, with Cd and Cr values averaging 380 and 320 µg/L, respectively, which are above safe limits. Se concentrations and high levels of Ca pose major safety and scaling concerns, respectively. We also compared Marcellus shale drilled core samples’ geochemical reactivity to samples collected from an outcrop. Full article

Water imbibition is a key factor affecting the flowback regime of shale gas wells after volume fracturing. In this study, a set of experimental apparatus and corresponding test and evaluation methods were developed to analyze the laws of forcible imbibition of water in a shale reservoir, characterize the initiation time of microfractures induced by shale hydration quantitatively, and optimize the shut-in time of shale gas wells; the imbibition depths of different pore types are quantitatively calculated based on the multiple pore imbibition analytical model. The experimental results show that: according to imbibition saturation growth rate, the shale forcible imbibition can be divided into three periods, imbibition diffusion, imbibition transition, and imbibition balance. Among them, the imbibition diffusion period is the main period for imbibition capacity rise. The reason for this phenomenon is that due to the fluid pressure difference effect, the shale fills its large pores and microfractures rapidly in the early stage, and in the percolation transition period, the percolation rate decreases continuously due to the gradual increase of fluid saturation. Due to the Jamin effect, it is difficult for the fluid to enter the small pores and the fluid fills the pore roar channel, the seepage saturation tends to stabilize, and the seepage equilibrium period appears. In the early period of shut-in, the imbibition capacity of shale increases significantly under the action of fluid pressure, providing a large amount of imbibition fluid for the spontaneous imbibition later. The imbibition depth of a clay pore was much greater than that of a brittle mineral pore and an organic pore. The reservoir confining pressure has prohibition on shale imbibition, but even under reservoir confining pressure, imbibition can still improve the fracturing effect of the reservoir, resulting in an increase in porosity of 0.42–1.63 times and an increase in permeability of 17.6–67.3 times. Under the experimental conditions, the initiation time of induced microfractures is 98.5 h on average and is in negative correlation with imbibition capacity. On this basis, the optimized shortest shut-in time of a shale gas well is 5 days. The study results can provide a scientific basis for the optimization of the flowback regime of shale gas reservoirs. Full article

The multifractal structure of shale pores significantly affects the occurrence of fluids and the permeability of shale reservoirs. However, there are few studies on the multifractal characteristics of shale pores that distinguish between organic and inorganic pores. In this study, we obtained the pore size distribution (PSD) of organic and inorganic shale pores separately by using a new NMR-based method and conducted a multifractal analysis of the structure of organic and inorganic shale pores based on PSD. We then investigated the geological significance of the multifractal characteristics of organic and inorganic shale pores using two multifractal characteristic parameters. The results showed that the structures of both organic and inorganic pores have multifractal characteristics. Inorganic pores have stronger heterogeneity and poorer connectivity compared to organic pores. The multifractal characteristics of inorganic pores significantly affect shale permeability and irreducible water saturation. Greater heterogeneity in the inorganic pore structure results in lower shale permeability and higher irreducible water saturation. Meanwhile, better connectivity leads to higher shale permeability and lower irreducible water saturation. The multifractal characteristics of organic pores significantly affect the shale adsorption capacity and have a weak impact on irreducible water saturation. Greater heterogeneity in the organic pore structure results in the shale having stronger adsorption capacity and higher irreducible water saturation The results also indicate that the multifractal characteristic parameters of inorganic pores can be regarded as an index for estimating the irreducible water saturation and flowback rate of fracturing fluid, and the multifractal characteristic parameters of organic pores can be regarded as an index for evaluating the quality of shale reservoirs. Full article